Common methods of drilling wells from the surface down through underground formations employ the use of a drill bit that is rotated by either a downhole motor (sometimes referred to as a mud motor), through rotation of a drill string extending from the surface, or through a combination of both surface and downhole drive mechanisms. Where a downhole motor is utilized, energy is typically transferred from the surface to the downhole motor by pumping a drilling fluid or “mud” down through a drill string and channeling the fluid through the motor causing the rotor of the downhole motor to rotate and drive the rotary drill bit. The drilling fluid or mud serves the further function of entraining rock cuttings and circulating them to the surface for removal from the well. In some instances the drilling fluid may also help to lubricate and cool the drill bit and other downhole components.
When drilling for oil and gas there are many instances where the underground formations that are encountered contain fluid (generally water, oil or gas) at very high pressures. Traditionally, when drilling into such formations a high density drilling fluid or mud is utilized in order to provide a high hydrostatic pressure within the wellbore to counteract the high fluid pressure. In such cases the hydrostatic pressure of the mud meets or exceeds the underground fluid pressure thereby ensuring well control and preventing a potential blowout. Where the hydrostatic pressure of the drilling mud is approximately the same as the underground fluid pressure, a state of balanced drilling is achieved. Due to the potential danger of a blowout in high pressure wells, in most instances an overbalanced situation is desired with the hydrostatic head of the drilling mud exceeding the underground formation pressure by a predetermined safety factor. The high density mud and the high hydrostatic head that it creates also helps to prevent a blowout in the event that a sudden fluid influx or “kick” is experienced when drilling through a particular underground formation that is under very high pressure, or when first entering a high pressure zone.
Unfortunately, such prior systems that employ high density drilling muds to counterbalance the effects of high formation pressures have met with only limited success. In order to create a sufficient hydrostatic head, the density of the drilling mud often has to be relatively high (for example from 15 to 25 pounds per gallon), necessitating the use of costly density enhancing additives. Such additives not only significantly increase the cost of the drilling operations, but can also present environmental difficulties in terms of their handling and disposal. High density muds may also not be compatible with many standard surface separation systems that are commonly in use. In typical surface separation systems the high density solids are removed preferentially to the drilled solids and the mud must be re-weighted to ensure that the desired density is maintained before it can be pumped back into the well.
High density drilling muds also present an increased potential for plugging downhole components, particularly where the drilling operation is unintentionally suspended due to mechanical, electrical, hydraulic or other failure. In addition, the high hydrostatic pressure created by the column of drilling mud in the string often results in a portion of the mud being driven into the formation, requiring additional fresh mud to be continually added at the surface and thereby further increasing costs. Invasion of the drilling mud into the subsurface formation may also cause irreparable damage to the formation.
Another limitation of such prior well pressure systems concerns the degree and level of control that may be exercised over the well. The hydrostatic pressure applied to the wellbore is primarily a function of the density of the mud and its depth or column height. For that reason there is only a limited ability to alter the hydrostatic pressure applied to the formation. Generally, varying the hole pressure requires an alteration of either the density of the drilling mud or the drilling fluid injection rate. The former can be an expensive and time consuming process, and the latter is limited and not always practical since it may have an adverse affect on the ability to clean the hole.
As a means to address some of the above deficiencies, others have suggested pumping fluids into the annulus of the well to thereby control bottom hole circulating pressure through controlling friction pressure. Such a method is described in U.S. Pat. No. 6,607,042, dated Aug. 19, 2003. While friction pressure methods of this sort may be effective in controlling bottom hole pressure, they can also increase the level of complexity of the overall drilling process, and necessitate the use of additional equipment that can have the result of increasing both capital and operating costs.
Still others have suggested controlling bottom hole pressure through the use of a surface back pressure system. Typically, such systems involve continuously monitoring borehole pressure to create a pressure model that is then used to predict fluctuations in downhole pressure. The model is continuously updated through the use of a computer or microprocessor that receives signals from downhole pressure sensors, flow meters and other such devices. The pressure model is then in turn used to control wellhead back pressure. Such a method is described in United States patent application publication number U.S. 2003/0196804, dated Oct. 23, 2003. As in the case of friction pressure systems, current surface back pressure systems add a significant level of complexity to the drilling operations, necessitate the use of additional equipment, and to a large extent are dependent upon the accuracy and predictability of a constantly changing downhole pressure model. Neither friction pressure nor currently available surface back pressure systems are designed to specifically counteract the effects of surge and swab pressures caused by the movement of the drill string.